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DNR updates legislature on AKLNG work
Commissioner Mack tells Senate Resources department disbanded dedicated gas team in 2016, working with consultants, existing staff
The Alaska Department of Natural Resources is working with the Alaska Gasline Development Corp. on the Alaska LNG project, Commissioner Andy Mack told the Senate Resources Committee March 21, but on a smaller scale than during the producer-led AKLNG project.
Mack said that when he became commissioner in 2016 DNR had an eight-person team dedicated to gas commercialization, positions budgeted specifically to that task. After the producers indicated they didn’t think the project would pass muster as an equity-based project, 2016 became a transition, Mack said. The members of the dedicated team were moved to other positions or laid off.
Steve Wright, formerly working interest owner representative for Chevron on the North Slope, was retained as senior advisor and consultant to the commissioner’s office, along with Black & Veatch.
Individuals within the department working on gas commercialization, such as DNR’s gas commercialization advisor Ed King, also have other duties, Mack said.
King and Wright joined Mack in the Senate Resources presentation.
RIK/RIV decision Mack said one of DNR’s primary responsibilities is the royalty-in-kind vs. royalty-in-value decision.
The statute establishing the state’s role, passed as Senate Bill 138 in 2014, specifies that DNR will elect to receive Alaska LNG royalty gas in kind, unless the DNR commissioner finds that taking gas in value would be in the best interest of the state.
Mack said that before entering a contract to take gas as royalty-in-kind the department would issue a preliminary best interest finding, take comments from the public and the Royalty Oil and Gas Development Advisory Board, and then obtain legislature approval before issuing a final best interest finding.
Any royalty-in-kind finding as to come to the Legislature for ratification - that’s been the process since there have been royalty contracts in the state, Mack said, and a RIK finding for a gas sale would follow the same process.
A BIF includes an analysis of impacts on Alaska consumers, the Alaska economy and state revenues.
Modeling Resources Chair Cathy Giessel, R-Anchorage, said legislators would be interested in seeing the modeling the department uses in making its decision, and asked if the department would be able to provide the ranges of gas price and project cost the department was considering. Mack said there would be an opportunity in confidential hearings for legislators to look at the data and for DNR to describe it privately.
That would be prior to publication of the BIF, Mack said, adding that he imagined the co-chairs of Senate Finance would also be interested.
Royalty gas disposition Wright said that under the current project structure, led by AGDC, if DNR elects to take the gas as royalty in kind, the state could sell the royalty gas, and the taxes as gas, to AGDC.
King said the state’s royalty share averages 14.5 percent at Point Thomson; at Prudhoe Bay all the leases have a 12.5 percent royalty. There is also the tax component, referred to as TAG, taxes as gas. King said the combination of the two works out to more than 24 percent of what is produced belonging to the state.
Wright said custody transfer of the gas to a buyer would be at the wellhead or at the inlet to the gas treatment plant and said DNR is engaged with AGDC on discussions for a gas sales agreement, which would require a recommendation from the royalty board and legislative approval.
King said that royalty in value would let the producers sell gas for the state. The state would then receive the same value the producers receive, with value determined at the wellhead, less allowable deductions.
Giessel asked if field cost allowances would come before the Legislature for approval. Mack said field costs are negotiated and that many are part of settlement agreements, which means DNR, the producers and the court all play a role.
Benefits, risks Wright reviewed the benefits and risks of RIK and RIV.
For RIK, AGDC’s purchase of royalty and TAG gas would support AGDC’s Alaska LNG marketing relationships and the state wouldn’t have to audit the producers’ gas sales. The risks of RIK include cost allocation for handling and disposing of carbon dioxide produced with the gas, locking in RIK for an initial project term and field cost allowance related to gas processing.
For RIV, the state would have no exposure to negative netback risk and receive value based on the price the producers get. Risks for RIV future uncertainties could include commodity prices and transportation deductions.
On the disposal issue, Wright said that under the producer-led project disposal at the Prudhoe Bay unit had been discussed, with compensation to the unit owner. He said some modeling had been done on reinjection for recovery, or disposal into shallow reservoirs for sequestration, but said that reservoir engineering work had not been completed when the state took over project leadership.
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